1. Field of the Disclosure
Embodiments disclosed herein relate generally to drilling an earth formation using a drilling fluid. In other aspects, embodiments disclosed herein relate to increasing rates of penetration when drilling an earth formation by using a drilling fluid comprising a base fluid and a micronized weighting agent, either coated or uncoated.
2. Background
Various fluids are used when drilling or completing a well, and the fluids may be used for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
In general, drilling fluids should be pumpable under pressure down through strings of drilling pipe, then through and around the drilling bit head deep in the earth, and then returned back to the earth surface through an annulus between the outside of the drill stem and the hole wall or casing. Beyond providing drilling lubrication and efficiency, and retarding wear, drilling fluids should suspend and transport solid particles to the surface for separation and disposal. In addition, the fluids should be capable of suspending additive weighting agents (to increase specific gravity of the mud), generally finely ground barites (barium sulfate), and transport clay and other substances capable of adhering to and coating the borehole surface.
Drilling fluids are generally characterized as thixotropic fluid systems. That is, they exhibit low viscosity when sheared, such as when in circulation (as occurs during pumping or contact with the moving drilling bit). However, when the shearing action is halted, the fluid should be capable of suspending the solids it contains to prevent gravity separation. In addition, when the drilling fluid is under shear conditions and a free-flowing near-liquid, it must retain a sufficiently high enough viscosity to carry all unwanted particulate matter from the bottom of the well bore to the surface. The drilling fluid formulation should also allow the cuttings and other unwanted particulate material to be separated from the liquid fraction after transport to the surface.
There is an increasing need for drilling fluids having the rheological profiles that enable wells, especially deep or horizontal wells, to be drilled more easily. Drilling fluids having tailored rheological properties ensure that cuttings are removed from the wellbore as efficiently and effectively as possible to avoid the formation of cuttings beds in the well which can cause the drill string to become stuck, among other issues. There is also the need from a drilling fluid hydraulics perspective (equivalent circulating density) to reduce the pressures required to circulate the fluid, this helps to avoid exposing the formation to excessive forces that can fracture the formation causing the fluid, and possibly the well, to be lost. In addition, an enhanced profile is necessary to prevent settlement or sag of the weighting agent in the fluid, if this occurs it can lead to an uneven density profile within the circulating fluid system, which can result in loss of well control, such as due to gas/fluid influx, and wellbore stability problems, such as caving and fractures.
Fluid characteristics required to meet these challenges include, for instance, that the fluid must be easy to pump, requiring the minimum amount of pressure to force the fluid through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools. In other words, the fluid should have the lowest possible viscosity under high shear conditions. Conversely, in zones of the well where the flow area is large, velocity of the fluid is low, where there are low shear conditions, or when the fluid is static, the viscosity of the fluid should be as high as possible in order to prevent settlement, suspend, and transport the weighting material and drilled cuttings. However, it should also be noted that the viscosity of the fluid should not continue to increase under static conditions to unacceptable levels. Otherwise, when fluid circulation is regained, this can lead to excessive pressures that can fracture the formation or alternatively can lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.
Wellbore fluids must also contribute to the stability of the well bore, and control the flow of gas, oil or water from the pores of the formation in order to prevent, for example, the flow or blow out of formation fluids or the collapse of pressured earth formations. The column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid. High-pressure formations may require a fluid with a specific gravity of 3.0 or higher.
A variety of materials are presently used to increase the density of wellbore fluids. These include dissolved salts such as sodium chloride, calcium chloride, and calcium bromide. Alternatively, powdered minerals such as barite, calcite and hematite are added to a fluid to form a suspension of increased density. The use of finely divided metal, such as iron, as a weighting material in a drilling fluid, wherein the weighting material includes iron/steel ball-shaped particles having a diameter less than 250 microns and preferentially between 15 and 75 microns, has also been described. The use of finely powdered calcium or iron carbonate has also been proposed; however, the plastic viscosity of such fluids rapidly increases as the particle size decreases, limiting the utility of these materials.
Conventional weighting agents such as powdered barite exhibit an average particle diameter (d50) in the range of 10-30 microns. To adequately suspend these materials requires the addition of a gellant such as bentonite for water-based fluids, or organically modified bentonite for oil-based fluids. A soluble polymer viscosifier such as xanthan gum may also be added to slow the rate of the sedimentation of the weighting agent. However, as more gellant is added to increase the suspension stability, the fluid viscosity (plastic viscosity and/or yield point) increases undesirably resulting in reduced pumpability. This is also the case if a viscosifier is used to maintain a desirable level of solids suspension.
The sedimentation (or “sag”) of particulate weighting agents becomes more critical in wellbores drilled at high angles from the vertical, in that a sag of, for example, one inch (2.54 cm) can result in a continuous column of reduced density fluid along the upper portion of the wellbore wall. Such high angle wells are frequently drilled over large distances in order to access, for example, remote portions of an oil reservoir. In such instances it is important to minimize a drilling fluid's plastic viscosity in order to reduce the pressure losses over the borehole length. At the same time a high density also should be maintained to prevent a blow out. Further, as noted above with particulate weighting materials the issues of sag become increasingly important to avoid differential sticking or the settling out of the particulate weighting agents on the low side of the wellbore.
Being able to formulate a drilling fluid having a high density and a low plastic viscosity is also important in deep high pressure wells where high-density wellbore fluids are required. High viscosities can result in an increase in pressure at the bottom of the hole under pumping conditions. This increase in “Equivalent Circulating Density” can result in opening fractures in the formation, and serious losses of the wellbore fluid into the fractured formation. Again the stability of the suspension is important in order to maintain the hydrostatic head to avoid a blow out. The goal of high-density fluids with low viscosity plus minimal sag of weighting material continues to be a challenge. Thus, there is a need for materials that increase fluid density while simultaneously providing improved suspension stability and minimizing both fluid loss and increases in viscosity.